Combustion flue gas NOx treatment

ABSTRACT

Combustion flue gas containing NO X  and SO X  is treated to remove NO X  in a multistep system in which NO X  is reduced in the flue gas stream via selective catalytic reduction or selective non-catalytic reduction with ammonia or an ammonia-forming compound, followed treatment with hydrogen peroxide to remove residual ammonia and, optionally, treatment with an alkali reagent to reduce residual NO X  in the flue gas stream. The NO X -depleted flue gas stream may also be subjected to a desulfurization treatment for removal of SO X .

FIELD OF THE INVENTION

The present invention relates to air pollution control and moreparticularly to the treatment of a combustion flue gas stream from astationary source to remove its NO_(X) contaminants before the gasstream is released into the atmosphere.

BACKGROUND OF THE INVENTION

Combustion of fuels such as coal, coke, natural gas or oil typicallyresults in the presence of pollutants in the combustion flue gas streamresulting from the combustion process or derived from impurities presentin the fuel source. Electric utility power plants that burn coal are asignificant source of such combustion process air pollutants, but otherstationary fuel-burning facilities such as industrial boilers, wasteincinerators, and manufacturing plants are also pollution sources.

The primary air pollutants formed by these stationary high temperaturecombustion sources are sulfur oxides (e.g., SO₂ and SO₃), also calledSO_(X) gases, and nitrogen oxides, also called NO_(X) gases, both ofwhich are acid gases. Other combustion pollutants of concern in thesecombustion flue gases include other acid gases such as HCl and HF, Hg(mercury), CO₂ and particulates. These individual pollutant componentsfrom stationary combustion sources have been subject to increasinglymore stringent regulatory requirements over the past three decades, andemission standards are likely to be tightened in the future.

The removal or significant reduction of SO_(X) and NO_(X) contaminants,as well as other acid gases and elemental mercury, requires anintegrated air pollution control system. Such integrated air pollutioncontrol systems represent a particular challenge in situations requiringretrofitting of first-time or additional or enhanced pollution controlmeasures, e.g., older coal-fired electric power plants without anydesulfurization measures or power plants with SO_(X) controls requiringmodifications for control of NO_(X) gas emissions.

Nitrogen oxide or nitric oxide (NO) and smaller amounts of nitrogendioxide (NO₂) are the normal constituents of NO_(X) contaminants formedin the combustion of fossil fuels like coal, coke and oil. The presenceof NO_(X) in a flue gas stream discharged to the atmosphere can resultin a “brown plume” and is a contributor to ground-level ozone pollution(“smog”) and to acidifying nitrate deposition.

The wet scrubbing desulfurization techniques utilized for SO_(X) removalfrom combustion flue gas are largely unsuccessful for removal of NO thatis also present since the latter has low water solubility and is notamenable to aqueous alkali desulfurization scrubbing techniques.Although NO_(X) formation can be controlled to some extent by modifyingcombustion conditions, current techniques for NO_(X) removal fromcombustion flue gas normally utilize post-combustion treatment of thehot flue gas by Selective Catalytic Reduction (SCR) or SelectiveNon-Catalytic Reduction (SNCR)

The Selective Catalytic Reduction procedure utilizes a catalytic bed orsystem to treat a flue gas stream for the selective conversion(reduction) of NO_(X) to N₂. The SCR procedure normally utilizes ammoniaor urea as a reactant that is injected into the flue gas streamupstream, prior to their being contacted with the catalyst. SCR systemsin commercial use typically achieve NO_(X) removal rates of 80-90%, butimproved catalyst systems reportedly provide over 90% removal rates.

The Selective Non-catalytic Reduction procedure is analogous to SCRexcept that no catalyst is employed in the treatment of a flue gasstream with ammonia or urea for the selective reduction of NO_(X) to N₂.High treatment temperatures are required for the reduction reaction inSNCR. SNCR systems are favored for retrofit of smaller electric powerutility plants because of their simplified installation and modestequipment requirements. A drawback to commercial SNCR systems is theirNO_(X) removal rates of only 30-70%.

Many individual approaches are described in the prior art for theremoval of specific SO_(X) and NO_(X) components. In actual commercialpractice, the engineering challenge is the design of an integrated airpollution control system that can be retrofitted to existing fossil-fuelfired electric utility plants that are in need of updated or upgradedpollution controls for one or more of SO₂, SO₃, NO, NO₂, Hg, HCl, HF,CO₂ and particulates. Since individual electric utility plants arerarely alike, retrofit systems need to be adaptable to the specificrequirements and needs of the electric utility plant being modified.

The present invention provides an air pollution retrofit system for theeffective control of residual ammonia and NO_(X) in SCR-treated orSNCR-treated combustion flue gas streams, utilizing hydrogen peroxideand an alkali sorbent as reactants. The novel NO_(X) abatement retrofitsystem of this invention is not disclosed or suggested in prior arttreatments for abating SO_(X) and NO_(X) contaminants in combustion fluegas streams.

U.S. Pat. No. 4,213,944 of Azuhata et al. (Hitachi) discloses a processfor removing nitrogen oxides from a hot gas stream containing the sameby adding a reducing agent, preferably ammonia, and hydrogen peroxideinto hot gas stream at a temperature of 400-1200° C. to decompose thenitrogen oxides to nitrogen gas and water. The hydrogen peroxide isadded concurrently with the ammonia and is said to increase the activityof the ammonia, particularly at gas temperatures of 400-800° C., bydecomposing the ammonia to make it reactive with the NO_(x). Sufficienthydrogen peroxide is added with the ammonia so that excess unreactedammonia is also decomposed. U.S. Pat. No. 4,213,944 of Azuhata et al. ishereby incorporated by reference for its disclosures about the reactionof H₂O₂ and NH₃ and related reactions.

U.S. Pat. Nos. 5,120,508, and 4,783,325 of Jones (Noell) disclosemethods of converting NO to NO₂ in a flue gas stream by injecting a gascontaining a peroxyl initiator and oxygen into the NO-containing gasstream. The peroxyl initiator is preferably propane but may also beother hydrocarbons or hydrogen peroxide or hydrogen. The resultantNO₂-containing gas stream is then treated in an absorption section toremove NO_(X) and SO_(X) with a dry sorbent such as nahcolite or trona,the dry sorbent being captured in a baghouse before the treated gasstream is discharged to the atmosphere.

U.S. Pat. No. 5,670,122 of Zamansky et al. (Energy & EnvironmentalResearch) discloses a method for removing NO, SO₃, CO, lighthydrocarbons and mercury vapor (Hg) from combustion flue gas byinjecting into the gas stream atomized droplets of either hydrogenperoxide or a mixture of hydrogen peroxide and methanol, to convert therespective gas contaminants to NO₂, SO₂, CO₂ (for the CO and lighthydrocarbons) and HgO. The treatment is carried out at a gas temperatureof about 377° C. to about 827° C., and the reaction products aresubsequently removed in a downstream scrubbing operation. The treatmentalso may be carried out in combination with SNCR NO_(X) reductiontechnology, with the SNCR-treated combustion gas stream being treateddownstream with the H₂O₂ or H₂O₂/CH₃OH injection treatment.

U.S. Pat. No. 6,676,912 of Cooper et al. (NASA) discloses a method ofremoving NO from stationary combustion gas streams by injection of H₂O₂into the gas stream to oxidize NO to NO₂ and HNO₃ and HNO₂, whichspecies are more readily recovered via aqueous wet scrubbing. Thenitrogen acids and residual NO₂ are then removed via wet scrubbing withwater or an aqueous alkaline medium or via passage of the flue gasstream through a particulate alkaline sorbent in a baghouse. The methodmay optionally include a preliminary flue gas desulfurization scrubbingstep to remove SO₂, prior to the H₂O₂ injection. U.S. Pat. No. 6,676,912of Cooper et al. is hereby incorporated by reference for its disclosuresabout the reaction of H₂O₂ and NO_(X) and related reactions.

The present invention provides an air pollution retrofit system for theeffective downstream removal of residual ammonia in SCR-treated orSNCR-treated flue gas streams and, optionally, the further removal ofNO_(X) in the SCR-treated or SNCR-treated flue gas streams.

SUMMARY OF THE INVENTION

In accordance with the present invention, NO_(X) is removed from a fluegas stream in a method comprising subjecting a combustion flue gasstream containing NO_(X) to a selective catalytic reduction operation orselective non-catalytic reduction operation by injecting ammonia or anammonia-forming compound into the flue gas stream as an agent forreducing the NO_(x), wherein an excess of ammonia is introduced to yielda flue gas stream containing unreacted residual ammonia and a reducedconcentration of NO_(x); and thereafter injecting hydrogen peroxide intothe flue gas stream containing unreacted residual ammonia, in an amountsufficient to react with the residual ammonia present in the flue gasstream, to yield a flue gas stream having a reduced concentration ofresidual ammonia.

Another embodiment of the present invention is a method for removingNO_(X) from a flue gas stream comprising injecting ammonia or anammonia-forming compound into a combustion flue gas stream containingNO_(x), wherein an excess of ammonia is introduced into the flue gasstream as an agent for reducing the NO_(x), to yield a flue gas streamcontaining unreacted residual ammonia and a reduced concentration ofNO_(x); thereafter injecting hydrogen peroxide into the flue gas streamcontaining unreacted residual ammonia, in an amount sufficient to reactwith residual ammonia present in the flue gas stream, to yield a fluegas stream having a reduced concentration of residual ammonia; andcontacting the ammonia-depleted flue gas stream with an alkali reagentin an amount sufficient to remove NO_(X) present in the gas stream,yielding a flue gas stream with reduced concentrations of ammonia andNO_(x).

Still another embodiment of the present invention is a system forremoving NO_(X) from a flue gas stream containing NO_(X) and SO_(X)comprising a selective catalytic reduction unit or selectivenon-catalytic reduction unit for reducing the NO_(X) content of acombustion flue gas, in which ammonia or an ammonia-forming compound isinjected into a combustion flue gas stream containing NO_(X) and SO_(X)as an agent for reducing the NO_(x); a hydrogen peroxide injectionoperation, located downstream of the NO_(X) reduction unit, in whichhydrogen peroxide is injected into the ammonia-containing flue gasstream for reaction with residual ammonia present in the flue gasstream; and an alkali reagent treatment operation, located downstream ofthe hydrogen peroxide injection operation, in which alkali reagent iscontacted with the ammonia-depleted flue gas stream to react with NO_(X)present in the gas stream.

BRIEF SUMMARY OF THE DRAWING

The FIGURE is a schematic flow diagram illustrating a preferredembodiment of the combustion flue gas NO_(X) treatment process of thisinvention that is described in the Example.

DETAILED DESCRIPTION OF THE INVENTION

The present invention is directed to improved NO_(X) treatment processesthat utilize ammonia or an ammonia-forming compound to reduce NO_(X) incombustion flue gas streams from stationary sources, such as coal-firedelectric utility power plants. The present invention encompasses bothmethods of treating flue gas streams as well as systems intended forimplementing the inventive method.

Combustion flue gas streams treated with NH₃ or its equivalent in eitherselective catalytic reduction (SCR) procedures or selectivenon-catalytic reduction (SNCR) procedures normally contain residual,unreacted NH₃ as well as unreacted or partially-reacted NO_(X) in theSCR- or SNCR-treated flue gas stream.

The present invention provides for the removal of the residual unreactedNH₃ from the NH₃-containing flue gas stream and, further, for thefurther reaction of unreacted NO_(X) (e.g., NO) or partially-reactedNO_(X) (e.g., NO₂) in the SCR- or SNCR-treated flue gas stream. Theinvention is particularly useful in the treatment of NH₃-containingSNCR-treated flue gas streams, which typically contain unreacted ammoniaand substantial concentrations of unreacted or partially reacted NO_(x),as explained in more detail below.

In the present invention, residual unreacted NH₃ in an NH₃-containingflue gas stream is removed using hydrogen peroxide. The unreacted orpartially reacted NO_(X) (e.g., NO and NO₂) in a SCR- or SNCR-treatedflue gas stream may then, optionally but preferably, be reacted furtherwith an alkali reagent, to provide an NH₃-free and NO_(x)-depleted fluegas stream. The SO_(X) in the combustion flue gas stream may also beremoved in desulfurization operations, in conjunction with the treatmentprocedures of the present invention.

Combustion Flue Gas Stream

The combustion flue gas stream exiting the combustion zone of astationary source contains a variety of components that are desirablyreduced or removed from the flue gas prior to its being discharged tothe atmosphere, among which are the NO_(X) components treated accordingto the present invention. The precise composition of the combustion fluegas depends primarily on the nature of the fuel and on the furnacedesign and operating parameters. For example, the fuel may be, e.g.,coal, oil, coke or natural gas, etc., and in the case of coal, coal maybe high sulfur or low sulfur, bituminous or anthracite, etc.

A representative flue gas stream obtained from combustion of high sulfurcoal containing 2.5 wt % sulfur, burned using 10% excess air, has thecomposition shown in Table 1.

TABLE 1 Flue Gas Composition Component Concentration: volume basis NO350-400 parts per million (ppm) NO₂ 10-20 ppm SO₂ 0.22%   SO₃    20 ppmH₂O  9% CO₂ 15% Hg 1 part per billion (ppb) Other Gases 76%

The NO concentration in the flue gas stream is typical of that expectedfrom the burning of high sulfur coal in a furnace that is not equippedwith low NO_(x) burners. The NO₂ concentration typically representsabout 5% of the total NO_(x). The SO₂ concentration in the flue gasstream is relatively high, as would be expected from the burning of highsulfur coal. The SO₃ concentration is typically only about 1% of the SO₂concentration.

The foregoing flue gas composition is simply meant to be illustrative ofa typical combustion flue gas stream. The present invention is adaptedto be used with a wide range of different flue gas compositions and airpollution control systems, within the parameters described in moredetail below.

The present invention is intended for use with combustion flue gas airpollution control systems that utilize an NO_(X) treatment based onselective catalytic reduction of NO_(X) or selective non-catalyticreduction of NO_(X) using ammonia or an ammonia-forming reducing agent,resulting in flue gas streams that contain residual ammonia and alsocontain some unreacted or partially reacted NO_(x).

Ammonia Injection—SCR-SNCR

The NO_(X) treatment method of the present invention involves an initialNO_(X) treatment of a NO_(X)-containing combustion flue gas stream in atreatment step, i.e., unit operation, which is a selective catalyticreduction (SCR) reaction or a selective non-catalytic reduction (SNCR)reaction, using ammonia or an ammonia-forming compound as the reducingagent.

The preferred reducing agent for the SCR or SNCR treatment of thisinvention is ammonia. Ammonia is a well known and widely-availablechemical that is normally a gas at room temperature and pressure. Theammonia may be injected or otherwise introduced into the combustion fluegas stream either in anhydrous form or aqueous form, e.g., an aqueousammonia solution.

The reducing agent may also be urea (NH₂CONH₂), also called carbamide,which is a stable solid at room temperature. Urea is water soluble and,in the presence of water, will gradually hydrolyze to form ammoniumcarbamate (H₂N—COONH₄), which itself slowly decomposes into ammonia andcarbon dioxide. Urea is preferably injected into the combustion flue gasstream in the form of an aqueous solution or slurry.

The reducing agent used in the present invention may also be otherNH₃-forming or NH₃-like compounds, such as cyanuric acid ((CNOH)₃) alsoknown as 1,3,5-triazine-2,4,6-triol, ammonium sulfate ((NH₄)₂SO₄), andhydrazine (N₂H₄).

The selective catalytic reduction (SCR) of NO_(X) in the presentinvention is carried out in a conventional manner, using SCR equipmentand procedures well known to those skilled in the art. The SCR reactoris equipped with a catalyst bed, which is preferably in modular form(e.g., extruded ceramic honeycomb or plates) but which can also be inthe form of pellets or the like. In addition to the catalytic reactor,the other components of the SCR system include a reagent storage andinjection system, e.g., tanks, vaporizers, pre-heaters, pumps, mixers,injectors, associated controls, and NO_(X) continuous emissionsmonitors.

The ammonia (or urea or other NH₃-forming compound) is injected orotherwise introduced into the NO_(X)-containing combustion flue gasstream upstream of the catalyst in the SCR reactor. The injection may becarried out with conventional gas (e.g., for anhydrous ammonia) orliquid injection (e.g., for aqueous ammonia) equipment.

The selective reduction reaction involves the catalyzed reductionreaction of NO_(X) with NH₃ (the reducing agent) to form N₂, andnormally some NO₂ intermediate, and H₂O. The selective in SCR refers tothe preference of the ammonia to react with NO_(X) and not otherpollutant species in the flue gas stream. In actual practice, SCRtreatment of SO_(X)- and NO_(X)-containing flue gas streams typicallyresults in the catalyzed formation of some by-product SO₃ from SO₂.Efficient catalyst performance in the SCR reaction requires the presenceof oxygen, with at least 2-3 vol % O₂ preferably being present.

The reactions in selective catalytic reduction, as well as in selectivenon-catalytic reduction, of a NO_(X)- and SO_(X)-containing combustionflue gas using ammonia as the reducing agent are believed to include thefollowing stoichiometric reactions:

Primary Reactions:4NO+4NH₃+O₂→4N₂+6H₂O  (1)2NO₂+4NH₃+O₂→3N₂+6H₂O  (2)NO+NO₂+2NH₃→2N₂+3H₂O  (3)

Secondary Reactions:2SO₂+O₂→2SO₃  (4)2NH₃+SO₃+H₂O →(NH₄)₂SO₄  (5)NH₃+SO₃+H₂O →NH₄HSO₄  (6)

Primary reaction for use of urea in lieu of ammonia:4NO+2(NH₂)₂CO+0₂→4N₂+4H₂O+2CO₂  (7)

The term normalized stoichiometric ratio (NSR) describes the N/NO molarratio of injected reagent (e.g., NH₃) to NO_(X) concentration,particularly NO which is the primary NO_(X) constituent, in the flue gasstream. The NSR is a measure of the amount of reagent added relative tothe amount theoretically required to react with the NO_(X) present. Itshould be evident from reactions (1) and (7) that use of ammonia as areactant theoretically requires 1 mole of NH₃ (NSR=1), but use of ureain lieu of ammonia would theoretically requires only ½ mole of urea.

In the actual operation of a SCR or SNCR operation, the ammonia or otherammonia-generating compound will typically not be completely reactedwith the NO_(X) species in the flue gas stream being treated, even atNSR=1. For example, a SNCR operation employing stoichiometric amounts ofammonia with about 10% excess air may result in about 10 ppm (byvolume), or more or less, unreacted ammonia (also called ammonia slip)in the effluent gas stream. A SCR operation employing stoichiometricamounts of ammonia with about 10% excess air may result in about 5 ppm(by volume), or more or less, unreacted ammonia in the effluent gasstream.

For both SCR and SNCR operations, increasing the amount of reagent usedbeyond the stoichiometric amount required will generally provide adesirable increase in the amount of NO_(X) reduction. However, suchincreased NO_(X) reductions will also result in increased concentrationsof unreacted reagent (i.e., ammonia or urea) remaining in the treatedflue gas stream, normally an undesirable consequence.

The present invention, however, provides an efficient means for removingany unreacted ammonia that passes through the SCR operation or NSCRoperation and is contained in the downstream flue gas stream.Consequently, the preferred operation of SCR and SNCR procedures in thepresent invention calls for use of a stoichiometric excess of ammonia(or ammonia-forming compound), based on the amount of NO_(X) in the fluegas stream entering the SCR or SNCR operation. The ammonia is preferablyintroduced into flue gas stream in an amount sufficient to provide astoichiometric molar excess, with an NSR greater than 1, based on theamount of NO_(X) present in the flue gas stream, and more preferably isintroduced in a stoichiometric excess such that the NSR is at leastabout 1.2 up to about 5, and most preferably is introduced in astoichiometric excess such that the NSR is at least about 1.5 (50%excess). A maximum NSR of about 3 is most preferred.

In the present invention, a wide variety of conventional catalystcompositions may be utilized in the SCR reactor, and such catalystcompositions are well known to those skilled in the art. The catalyst(the catalytically-active metal) selection will typically depend on thecombustion flue gas stream treatment temperature. The catalyst substratewill normally be selected based on the type of reactor or reactorconfiguration used.

The primary factor that affects SCR operational efficiency is the choiceof catalyst and reactor bed catalyst design; other factors includetemperature, catalyst bed residence time (a fraction of a second up toabout a second), reagent injection rate, reagent-flue gas mixing, andflue gas NO_(X) concentration. Treatment temperatures for SCR can varywidely, e.g., about 350° F. to about 1100° F., and depend on the choiceof catalyst and the upstream/downstream location of the SCR reactorwithin flue gas air pollution control system in use at the facility inquestion. Typical SCR NO_(X) removal efficiencies range from about 80%to at least about 90% NO_(X) reduction.

At SCR operating/treatment temperatures of about 450° F. to about 800°F., the SCR catalyst is preferably selected from base metal catalysts,e.g., typically titanium and vanadium oxides, which also may containmolybdenum, tungsten, and other elements.

A preferred treatment temperature range for SCR operation is about 600°F. to about 675° F. In many electric utility power plants, the preferredSCR operating temperature range of about 600° F. to about 675° F. isreadily obtained by locating the SCR reactor so as to treat the flue gasstream downstream of the economizer and upstream of the air pre-heater.This preferred temperature range typically provides for maximizedconversion of NO_(X) with a catalyst choice optimized for thistemperature range, e.g., reaction efficiencies of at least about 90%NO_(X) conversion or higher are possible.

A SCR reactor can also be operated at lower or higher temperatures thanthe preferred ranges noted above, with a suitable catalyst selection. Atlow SCR treatment temperatures, e.g., about 350° F. to about 550° F.,precious metal catalysts are preferred, e.g., platinum and palladium. Atvery high SCR treatment temperatures, e.g., about 675° F. to about 1100°F., zeolite catalysts are preferred.

In the present invention, selective non-catalytic reduction (SNCR) ofNO_(X) may also be employed in an initial NO_(X) treatment operation.The selective non-catalytic reduction of NO_(X) is operated without thebenefit of a catalyst that facilitates the reduction reaction in SCR.Consequently, the temperature of the flue gas stream at which the SNCRprocedure is carried out must be relatively high, about 1500° F. toabout 2100° F. The SNCR reactor is typically located just downstream ofthe combustion unit, so as to utilize the very hot flue gas exiting thecombustion unit, and upstream of the economizer. It is possible toexpand the lower end of this temperature treatment range by the additionof suitable chemical additives, as well as providing long residencetimes.

Like the SCR procedure, a selective non-catalytic reduction reaction iscarried out in a conventional manner, using SNCR equipment andprocedures well known to those skilled in the art. The principalcomponents of the SNCR system are a reagent storage and injectionsystem, e.g., tanks, vaporizers, pre-heaters, pumps, mixers, injectors,associated controls, and NO_(X) continuous emissions monitors. Theinjection may be carried out with conventional gas (e.g., for anhydrousammonia) or liquid or gas/liquid injection (e.g., for aqueous ammonia)equipment.

Factors that affect the SNCR operational efficiency include temperature,residence time, reagent injection rate and amount, reagent-flue gasmixing, and flue gas NO_(X) concentration. Generally, if the reagent isadequately mixed with the NO_(x)-containing flue gas at the propertemperature and is given an adequate residence time (a fraction of asecond to a few seconds), then satisfactory SNCR efficiencies will beachieved. Typical SNCR NO_(X) removal efficiencies range from about 30%to about 70% NO_(X) reduction.

The present invention is particularly suited for use with SNCR NO_(X)abatement procedures. Reaction efficiencies for SNCR NO_(X) treatmentcan be improved by use of increased or larger amounts of ammonia in theSNCR operation, yet this invention provides means for removing unreactedammonia (ammonia slip) downstream of the SNCR operation, as well asresidual NO_(X), as described below.

Hydrogen Peroxide Treatment

The flue gas stream, after being treated with ammonia or ammonia-formingreagent via the SCR or SNCR procedure, is next subjected to treatmentwith aqueous hydrogen peroxide in the method of this invention, toreduce the concentration of residual (unreacted or otherwise unused)ammonia in the SCR- or SNCR-treated flue gas stream.

The aqueous hydrogen peroxide is injected into the SCR- or SNCR-treatedflue gas stream, in an amount sufficient to react with at least aportion of the residual ammonia present in the NH₃-containing flue gasstream. The amount of hydrogen peroxide used with respect to the ammoniapresent in the flue gas stream is preferably in the range of from about¼ mole H₂O₂ per mole NH₃ up to about 15 moles of H₂O₂ per mole NH₃.

More preferably, the molar ratio of hydrogen peroxide to the ammoniapresent in the flue gas stream is in the range of from about ½ mole H₂O₂per mole NH₃ up to about 10 moles of H₂O₂ per mole NH₃. Most preferably,the hydrogen peroxide is used in an amount that provides a molar excesswith respect to the molar amount of ammonia present in the flue gasstream. The hydrogen peroxide is also most preferably used in an amountthat provides up to about 5 moles of H₂O₂ per mole NH₃ present in theflue gas stream.

Since the hydrogen peroxide in this invention is targeted for removal ofresidual ammonia (and not added upstream during the SCR or SNCRprocedure where ammonia is introduced), the amount of hydrogen peroxiderequired is minimized, as contrasted with its prior art use to catalyzethe reduction reaction of NO_(X) with ammonia upstream, as in Azuhata etal., U.S. Pat. No. 4,213,944.

The amount of hydrogen peroxide contacted with the NH₃-containing fluegas stream is desirably sufficient to reduce the ammonia concentrationin the H₂O₂-treated flue gas stream to less than about 10 ppm (byvolume) NH₃. In the preferred excess amounts, the hydrogen peroxidecontacted with the NH₃-containing flue gas stream can reduce the ammoniaconcentration in the H₂O₂-treated flue gas stream to less than about 5ppm NH₃ and, within the preferred temperature ranges, to less than about3 ppm NH₃.

The aqueous hydrogen peroxide may be injected into the NH₃-containingflue gas stream using conventional gas-liquid or liquid injectionequipment. The aqueous hydrogen peroxide is preferably injected, i.e.,introduced, into the flue gas stream as an atomized fine spray throughone or more nozzles. The nozzles should be designed to provide uniformdispersal and good mixing of the hydrogen peroxide into theNH₃-containing flue gas stream. In the case of extremely hot flue gasstreams, the injection system design should include provisions forensuring that the aqueous hydrogen peroxide does not become overheated(and vulnerable to decomposition) prior to its introduction into the hotflue gas stream.

The aqueous hydrogen peroxide used in the present invention may have awide range of aqueous solution concentrations, with aqueous solutionscontaining about 10 wt % to about 50 wt % H₂O₂ being preferred and thosecontaining about 20 wt % to about 40 wt % H₂O₂ being more preferred.Aqueous hydrogen peroxide solutions within these concentration rangesare readily available from commercial suppliers, as stabilized H₂O₂solutions.

Concentrations of aqueous H₂O₂ above 50 wt % H₂O₂ are feasible butrequire stringent handling and safety measures and are best avoided forthat reason. Concentrations of aqueous H₂O₂ below 10 wt % H₂O₂ arelikewise feasible but are relatively dilute, requiring relatively largervolumes to provide the same amount of H₂O₂ as provided in much smallervolumes of more concentrated aqueous solutions.

The activity of the hydrogen peroxide in its reaction with residualammonia may optionally be enhanced or increased, in the presentinvention, by the use of one or more activators in conjunction with theaqueous hydrogen peroxide. The activator may be introduced into theaqueous hydrogen peroxide solution shortly before the latter is injectedinto the NH₃-containing flue gas stream or may be introducedconcurrently with the aqueous hydrogen peroxide solution during theinjection procedure, provided that there is good mixing between the two.

Activators for hydrogen peroxide include metal ions (e.g., iron, copper,manganese, chromium, nickel), metals (e.g., platinum, silver) and metalcompounds (e.g., oxides, hydroxides or sulfides, e.g., of manganese,iron, copper, palladium). A preferred activator is iron and, as isevident for the exemplified metals, transition metals, including theheavy metals, are also preferred. Combinations of metal activators maybe used, with iron and copper being a preferred synergistic combination.

Other materials that may be used as hydrogen peroxide activators in thepresent invention include oxidizing agents such as ozone, hypochlorite(e.g., sodium or calcium hypochlorite), chlorite (e.g., sodiumchlorite), chlorate (e.g., sodium, potassium, or magnesium chlorate),and the like.

The hydrogen peroxide activator may be introduced into the aqueoushydrogen peroxide solution in dissolved form or in suspended form. Smallamounts of activator, in the range of parts per million, are normallysufficient to enhance the hydrogen peroxide activity. Theactivator-enhanced activity of the hydrogen peroxide extends not only tothe removal of residual ammonia but also to the reaction of hydrogenperoxide with other components in the flue gas, e.g., NO_(X).

Residence time required for reaction of the hydrogen peroxide andresidual ammonia is typically very short, from a fraction of a second,e.g., 0.01 second, to less than a few seconds, e.g., up to about 5seconds. Preferred residence times are generally less than about 2seconds. The optimum residence time will normally depend on thetemperature of the flue gas stream, with higher gas temperaturesproviding more rapid reaction.

The temperature range for the hydrogen peroxide treatment in the fluegas stream normally depends on the point or location at which thehydrogen peroxide is injected into the residual NH₃-containing flue gasstream, downstream of the SCR or SNCR treatment. As was noted in theearlier discussion of the SCR and SNCR treatments, the flue gastemperature for these NO_(X) treatment procedures can vary over wideranges.

In general, special gas temperature adjustments (i.e., heating orcooling steps) are not required for the flue gas stream as aprerequisite of the hydrogen peroxide treatment step. The hydrogenperoxide injection, in the present invention, may be carried out withthe flue gas stream temperature at whatever temperature the flue gasstream happens to be downstream of the SCR or SNCR treatment operation.

Consequently, the hydrogen peroxide treatment may be carried out withflue gas stream temperatures ranging from about 250° F. to about 1100°F. for SCR-treated flue gas streams. Flue gas temperatures of within therange of about 250° F. to about 800° F. are preferred for SCR-treatedflue gas streams, for the hydrogen peroxide injection step.

In the case of SNCR-treated gas streams, which are typically subjectedto SNCR treatment at high flue gas stream temperatures, the hydrogenperoxide injection step may be carried out with SNCR-treated flue gasstream temperatures ranging from about 250° F. to about 1500° F., withabout 250° F. to about 1100° F. being preferred, and about 250° F. toabout 800° F. being more preferred. The preferred lower temperatures arepossible by locating the hydrogen peroxide injection point downstream ofthe economizer in the flue gas stream ducting from an electric utilitypower plant.

The hydrogen peroxide treatment is primarily directed to removal ofresidual NH₃ in the flue gas stream downstream of the SCR or SNCRprocedure, and, as noted above, an excess of hydrogen peroxide (withrespect to the NH₃ in the flue gas stream) may be employed to this endin the present invention. Any unreacted hydrogen peroxide excess thatremains after its reaction with the residual ammonia is also availableto react with other contaminants in the flue gas stream, converting themto less objectionable or more readily removed species.

Such other contaminants that are vulnerable to reaction with H₂O₂include unreacted NO in the SCR-treated or SNCR-treated flue gas stream;mercury (Hg), typically present in small but significant amounts, about2 ppb or less; CO, typically present at less than 500 ppm (by volume);and unreacted light hydrocarbons. The reaction of hydrogen peroxide withNO is believed to result in the formation of NO₂ and/or related species,which may be removed via the optional alkali reagent treatment describedbelow. Consequently, any excess hydrogen peroxide remaining afterreaction with the residual ammonia can serve to enhance the overallpollution reduction in the flue gas stream.

Alkali Reagent Treatment

In another embodiment of the present invention, the ammonia-depletedflue gas stream is also treated with an alkali reagent, to effectfurther removal of residual NO_(X) present in the SCR- or SNCR-treatedflue gas stream. The residual NO_(X) species present in the H₂O₂-treatedand NH₃-depleted flue gas stream are typically NO₂ and NO. The NOcomponent of the residual NO_(X) is typically present in lowconcentrations, since the excess ammonia in the SCR or SNCR operation ofthis invention facilitates conversion of NO to N₂ and, in addition, anyexcess hydrogen peroxide in the NH₃ removal step is believed tofacilitate conversion of NO to NO₂. It should be noted that residual NO₂and NO in the H₂O₂-treated and NH₃-depleted flue gas stream differ intheir ease of removal; NO₂ is water soluble and therefore more readilyreacted, whereas NO is relatively water-insoluble.

The alkali reagent is utilized in either a wet or a dry treatment of theNH₃-depleted flue gas stream containing residual NO_(X). Severalapproaches may be used for contacting the alkali reagent with theNH₃-depleted NO_(X)-containing flue gas stream.

The alkali reagent may be contacted with the flue gas stream (i) as adry sorbent, e.g., by injection of dry particulate sorbent into the fluegas stream; (ii) as a slurry of particulate sorbent in admixture withwater, e.g., by injection of the aqueous slurry of particulate sorbentinto the flue gas stream; (iii) as a solution of water-soluble orpartially water-soluble reagent in an aqueous medium, e.g., by injectionof the aqueous reagent solution into the flue gas stream via a spraydrying technique; or (iv) as an aqueous solution or aqueous slurry ofwater-soluble or partially water-soluble reagent using a conventionalwet scrubber or absorber with the reagent in an aqueous medium as thescrubber/absorber liquid medium.

The ammonia-depleted flue gas stream, typically still containingresidual NO_(X), is treated with the alkali reagent in the presentinvention, to effect additional removal of the NO_(X) present in theflue gas stream. The alkali reagent treatment of the NH₃-depleted fluegas stream is normally carried out downstream of the hydrogen peroxidetreatment step. The alkali reagent treatment may be carried out as a onestep procedure or multistep (e.g., two steps or stages) procedure.

The alkali reagent material is selected on the basis of its ability,when introduced into, or injected into, or otherwise contacted with theNO_(X)-containing flue gas stream, to react or otherwise combine withNO_(X) present in the flue gas stream to effect removal of the NO_(X)components as flue gas stream contaminants.

The alkali reagent may be selected from any of several known alkalicompounds but is preferably a soda-type reagent containing NaHCO₃ and/orNa₂CO₃. The alkali reagent may also be lime (CaO), slaked lime (Ca(OH)₂)or limestone (CaCO₃), optionally in combination with a soda-typereagent.

Preferred alkali reagents for use in the present invention are soda-typereagents, both those containing NaHCO₃ and those containing Na₂CO₃, aswell as combinations of these. Such soda-type alkali reagents includeNaHCO₃-containing materials such as trona (a natural mineral containingNa₂CO₃.NaHCO₃.2H₂O), sodium sesquicarbonate (refined or re-crystallizedtrona, Na₂CO₃.NaHCO₃. 2H₂O), nahcolite (a natural mineral containingNaHCO₃), sodium bicarbonate (NaHCO₃), and wegscheiderite (a naturalmineral containing Na₂CO₃.3NaHCO₃). Soda ash (Na₂CO₃) is anothersuitable alkali reagent for use in the present invention. Mixtures oftwo or more these soda reagents may also be used as the alkali reagent.Trona and soda ash are preferred alkali reagents.

The interaction between the NO_(X) in the flue gas stream and alkalireagent that is a NaHCO₃-containing soda reagent is believed to includereaction between NO₂ and NaHCO₃ yielding a nitrate salt with byproductcarbon dioxide and water. This reaction appears to be facilitated orotherwise catalyzed by the presence of moisture and/or SO₂ in the fluegas stream. In addition, it is believed that residual NO in the flue gasstream may also react with a NaHCO₃-containing soda reagent in ananalogous reaction when the flue gas stream is contacted with aNaHCO₃-containing soda reagent.

The following additional reaction may occur, involving both the NO₂ andSO₂ present in the in the flue gas stream treated with an alkali reagentthat is a NaHCO₃-containing soda reagent:SO₂+½NO₂+2NaHCO₃→Na₂SO₄+½N₂+2CO₂+H₂O  (8)Reaction (10) is an overall reaction that appears to involve thefollowing two reactions:SO₂+2NaHCO₃→Na₂SO₃+H₂O+CO₂  (9)NO₂+2Na₂SO₃→2Na₂SO₄+½N₂  (10)

The amount of alkali reagent introduced into contact with theNO_(X)-containing flue gas stream for residual NO_(X) removal isnormally relatively modest, since the upstream SCR or SNCR NO_(X)reduction procedure typically effects a significant decrease in NO_(X)concentration in the flue gas stream. It should be recognized that theconcentration of NO_(x)-in the flue gas stream will vary, depending onwhether the upstream NO_(X) reduction procedure utilized SCR, typicallyresulting in 80-90% conversion of the NO_(X) to N₂, or SNCR, typicallyresulting in only about 50% conversion of the NO_(X) to N₂.

Sufficient alkali reagent is employed, either as dry sorbent or asreagent in an aqueous medium, to reduce the NO₂ concentration in thealkali reagent-treated flue gas stream to less than about 80% of itsconcentration in the SCR or SNCR-treated and NH₃-depleted flue gasstream, prior to treatment with the alkali reagent. Preferably, thealkali reagent treatment is sufficient to reduce the NO₂ present in thetreated flue gas stream to less than about 50%, and more preferably lessthan about 30%, of its concentration in the SCR or SNCR-treated andNH₃-depleted flue gas stream.

The alkali reagent employed in the present invention is normallysufficient, when contacted with the H₂O₂-treated, ammonia-depleted fluegas stream, to reduce the residual NO₂ concentration to less than about50 ppm (by volume) NO₂. The alkali reagent is preferably employed inamounts and under conditions sufficient to reduce the residual NO₂concentration to less than about 30 ppm NO₂, and more preferably to lessthan 20 ppm NO₂ and most preferably to less than 10 ppm NO₂, in thetreated flue gas stream discharged into the atmosphere.

The amount of alkali reagent introduced into and contacted with the fluegas stream should provide at least one mole of sodium (for NaHCO₃- orNa₂CO₃-containing reagents) or at least ½ mole of calcium (for CaO andother calcium-containing reagents), as the case may be, based on theamount of NO₂ present in the H₂O₂-treated and NH₃-depleted flue gasstream. Preferably, the amount of introduced alkali reagent provides atleast two moles of sodium based on the amount of NO₂ present in the fluegas stream being treated with a soda-type alkali reagent.

If the alkali reagent is utilized in the form of a dry particulatesorbent, the sorbent is preferably introduced into the flue gas streamin admixture with water, e.g., as a slurry, or into a humidified fluegas stream that has had moisture separately introduced. The addition orpresence of moisture in the NO_(X)-containing flue gas steam is believedto enhance the reaction of the NO_(X) in the flue gas with theintroduced sorbent, facilitating removal of the NO_(X) from the fluegas.

When the alkali reagent is employed in dry form, e.g., as a dry sorbentfor injection as a particulate solid into the flue gas stream, thereagent is preferably a NaHCO₃-containing compound, selected from one ormore of the containing NaHCO₃-containing materials named above and isemployed in finely-divided form.

The particulate alkali sorbent should have a relatively small particlesize in order to maximize the surface-to-volume ratio, i.e., therebyenhancing the effectiveness of the gas-solid interaction between the NO₂and alkali sorbent. The mean particle size of the soda sorbent should beless than about 100 μm, preferably less than about 70 μm, and morepreferably less than about 40 μm.

Conventional grinding or milling equipment can be employed to achievethese sorbent particle size objectives, if commercially-availableparticulate alkali sorbents are not already available meeting theseparticle size requirements. The particle size ranges noted above fordry-injected alkali sorbents are also applicable to particulate alkalireagents that are introduced into the flue gas stream as an aqueousslurry.

The alkali sorbent is injected as a dry particulate solid into theNO₂-containing flue gas stream using conventional solids injectionequipment, e.g., a screw conveyor, rotary lock valve with blower orother pneumatic injection device, with the proviso that uniformdispersal of the dry sorbent throughout the flue gas stream is desired,to ensure efficient interaction between the sorbent and the NO₂ in theflue gas stream.

Likewise, introduction of an alkali reagent as either an aqueous slurryor as an aqueous solution containing the alkali reagent can be carriedout using conventional equipment, such as solids/liquid spray injectorsor nozzles or solution spray apparatus, e.g., used in in-duct injectionprocedures or in spray drying operations, that provides uniform and gooddispersal of the slurry or solution droplets throughout the flue gasstream. The aqueous liquid medium associated with the reagent is rapidlyevaporated in the hot flue gas stream, resulting in formation ofparticulate solids that remain entrained in the flue gas stream.

The entrained solids in the flue gas stream, whether injected drysorbent particles or dried particulates (from a slurry or solution), maybe captured downstream using the solids recovery equipment normally usedin a flue gas pollution control system. Such solids-collection devicesinclude conventional electrostatic precipitators or baghouse filters,typically used to remove fly ash and other solids from a flue gasstream.

As mentioned above, the alkali reagent may be contacted with the fluegas stream as a solution or slurry of water-soluble or partiallywater-soluble reagent in an aqueous medium, e.g., by using aconventional wet scrubber or absorber with the water-soluble reagent asthe scrubber/absorber liquid medium.

In this embodiment of the invention, the NO_(X)-containing flue gasstream, containing very low concentrations of NH₃ but still containingresidual NO_(X), is passed through the wet scrubber or absorber andcontacted with the scrubber/absorber liquid containing the water-soluble(or partially water-soluble) reagent. The contact procedure is normallycarried out in a countercurrent flow fashion. Preferred reagents for wetscrubbing or absorption are soda ash, lime, hydrated lime and limestonein an aqueous medium.

The resulting flue gas stream exits the scrubber/absorber significantlydepleted in its NO_(X)-content. The spent scrubber/absorber liquid isnormally processed to recover the contaminants absorbed from the gasstream and then recycled with make-up alkali reagent for reuse.

In general and as with the hydrogen peroxide treatment, special gastemperature adjustments (i.e., heating or cooling steps) are notrequired for the gas stream as a prerequisite of the alkali reagenttreatment step, whether carried out with dry sorbent or with the reagentin a liquid medium. The alkali reagent NO_(X) treatment of the presentinvention may be carried out with the flue gas stream temperature atwhatever temperature the flue gas stream happens to be downstream of theSCR or SNCR treatment procedure. The flue gas temperature ranges willthus be similar to those stated above for the hydrogen peroxideinjection step, which is carried out upstream of the alkali reagentNO_(X) treatment step.

Consequently, the alkali reagent NO_(X) treatment may be carried outwith flue gas stream temperatures ranging from about 250° F. to about1100° F. for SCR-treated flue gas streams. Flue gas temperatures ofwithin the range of about 250° F. to about 800° F. are preferred forSCR-treated flue gas streams.

In the case of SNCR-treated gas streams, which are typically subjectedto SNCR treatment at high flue gas stream temperatures, the alkalireagent NO_(X) treatment may be carried out with SNCR-treated flue gasstream temperatures ranging from about 250° F. to about 1500° F., withabout 300° F. to about 1100° F. being preferred, and about 250° F. toabout 800° F. being most preferred. The preferred lower temperatures arepossible by locating the alkali reagent NO_(X) treatment pointdownstream of the economizer in the flue gas stream ducting in anelectric utility power plant.

Desulfurization

The present invention for enhanced NO_(X) reduction in NO_(X)- andSO_(X)-containing flue gas streams may also be employed in conjunctionwith desulfurization operations, for reduction or substantial removal ofSO_(X), e.g., SO₂ and/or SO₃.

Such optional desulfurization unit operations may be carried out eitherupstream or downstream of the NH₃ and NO_(X) treatment procedures of thepresent invention or even downstream of the H₂O₂ injection point butupstream of the NO_(X) alkali reagent treatment of this invention.Preferably, the desulfurization is carried out on the NH₃- andNO_(X)-depleted flue gas stream, downstream of the treatment proceduresof the present invention. This is particularly so in the case of wetdesulfurization operations being employed, since exiting flue gas streamtemperatures are significantly reduced upon passage through wetscrubbers or absorbers.

The SO_(X) in combustion flue gas streams is primarily sulfur dioxide(SO₂) and sulfur trioxide (SO₃). These SO_(X) components are normallyformed during the combustion of sulfur-containing (sour) fuels, such ascoal, coke or oil, and the flue gas streams that result from burningsuch sulfur-containing fuels, whether low-sulfur or high sulfur,consequently contain SO_(X) contaminants.

Sulfur dioxide is the predominant SO_(X) component in flue gas streams,with sulfur trioxide, SO₃, being produced in much smaller quantitiesthan SO₂. Concentrations of SO₂ in flue gas streams from coal firedboilers are typically substantial, e.g., about 0.01 vol % to about 0.5vol % SO₂, with about 0.05 vol % to about 0.3 vol % SO₂ being typical.

Typical concentrations of SO₃ in flue gas streams from coal firedboilers are about 10 ppm to about 30 ppm (by volume) SO₃. As mentionedearlier, pollution control operations to remove NO_(X) components fromthe flue gas stream, e.g., via selective catalytic reduction (SCR),often result in an unwanted increased concentration of SO₃, formed bythe catalytic oxidation of SO₂ in the flue gas stream during SCRtreatment, to levels that can double those normally present, e.g., toabout 20 to about 60 ppm or more SO₃. Likewise, the presence ofcatalytic metals, e.g., vanadium or nickel, in some fuels can alsoresult in the generation of additional sulfur trioxide.

These SO_(X) contaminants are desirably removed, or their concentrationsreduced, in the combustion flue gas stream via desulfurizationprocedures, prior to the flue gas stream being released into theatmosphere. Such desulfurization operations are readily incorporatedinto an integrated air pollution control system that utilizes thepresent invention for enhanced NO_(X) removal, in the treatment of aNO_(X)- and SO_(X)-containing combustion flue gas stream.

Desulfurization processes for removing SO₂ and/or SO₃ are well known inthe air pollution control field. Gas-liquid contactors or absorbers arewidely used to remove SO₂ from waste flue gas streams, using an alkalinereagent-containing aqueous medium, e.g., in wet scrubbing systemsutilizing lime, limestone or soda ash (sodium bisulfate). Conventionaltechniques for specific treatment of flue gas streams to reduce SO₃concentrations employ alkali reagents in wet scrubbing, slurry injectionor dry sorbent injection procedures. Some prior art desulfurizationprocedures are effective for removing both SO₂ and SO₃.

The present invention may be adapted for use with many conventionaldesulfurization systems, whether employed to remove SO_(X) componentsgenerally or SO₂ or SO₃ specifically. When used in conjunction with thepresent invention, such desulfurization systems are preferably locateddownstream, for desulfurization of the NH₃- and NO_(X)-depleted flue gasstream resulting from treatment according to the present invention. Wetdesulfurization systems are preferred for use in conjunction with thepresent invention, particularly wet scrubbing desulfurization systemsthat employ lime, limestone or soda ash.

Upstream desulfurization may be desirable in situations where flue gasstreams contain high concentrations of SO₃. Injection of a dry soda-typesorbent or slurried soda-type sorbent can be used to remove asignificant portion of SO₃ upstream of the ammonia treatment of aNO_(X)- and SO_(X)-containing flue gas stream. An advantage of suchupstream SO_(X) treatment is that excess ammonia can be used, e.g., inan SCR operation, without increasing the likelihood of excess ammoniareacting with SO₃ to form ammonium bisulfate or other sulfur salts thatmay lead to undesirable deposits in the flue gas ductwork or unitoperations equipment.

The following non-limiting Example illustrates a preferred embodiment ofthe present invention.

EXAMPLE

The Example illustrates the application of a preferred embodiment of thepresent invention to the NO_(X) and SO_(X) treatment of a flue gasstream from a combustion boiler utilizing high sulfur coal. The processis operated continuously, and normal steady state conditions are assumedfor purposes of the Example. The FIGURE illustrates a schematic flowdiagram of this preferred embodiment; reference numerals and letters inthe FIGURE are included in the process description which follows.References to gaseous component concentrations in percentage (%), partsper million (ppm) or parts per billion (ppb) refer to suchconcentrations on a volume basis.

The coal used in the combustion unit of this Example is high sulfur coalcontaining 2 wt % sulfur. The combustion furnace is operated withpreheated air, and it is assumed that there is 1% conversion of thesulfur in the coal to SO₃ in flue gas from the combustion unit. The exitcombustion flue gas stream 1 contains about 900 parts per million (ppm)SO₂, about 9 ppm SO₃ and about 420 ppm NO_(X), i.e., 400 ppm NO andabout 20 ppm NO₂.

Referring now to the FIGURE, the combustion flue gas stream 1 is passedthrough an economizer A, a gas-liquid heat exchange unit that reducesthe temperature of the hot combustion flue gas stream 1 from about 900°F. to about 700° F. The cooling medium is water (not shown in theFIGURE) which is heated in the economizer A prior to its being directedto the boiler associated with the combustion furnace.

The cooled flue gas stream 2 from the economizer A has essentially thesame composition as flue gas stream 1 and is then treated in a selectivecatalytic reduction reactor A to reduce its NO_(X) content. Thisselective catalytic reduction (SCR) unit operation reacts astoichiometric excess of ammonia 3 with NO_(X) contained in the flue gasstream 2 as the flue gas stream passes through the catalyst bed in theSCR reactor B. The ammonia 3 is employed in an amount that providestwice the stoichiometric amount required to react with the NO_(X) thatis contained in the flue gas stream 2.

The catalytic reduction reaction of NO_(X) in the SCR reactor B reducesthe NO content of the flue gas stream, producing N₂ and water. Thecatalytic reaction also increases the SO₃ content of the SCR-treatedflue gas by conversion of a small amount of SO₂ to SO₃.

The flue gas stream 4 exiting from the SCR unit operation B containsabout 890 ppm SO₂ and about 18 ppm SO₃ and reduced levels of NO_(X),about 50 ppm NO_(X). The flue gas stream 4 also contains residualunreacted ammonia, in an amount of about 10 ppm NH₃, since the ammoniawas used in excess and was therefore not completely reacted during theselective catalytic reduction reaction with NO_(X) in the SCR reactor B.

The residual NH₃-containing flue gas stream 4 is subjected to atreatment with hydrogen peroxide 5, which is injected into the flue gasstream 4 in unit H₂O₂ injection unit operation shown as block C in theFIGURE. The hydrogen peroxide 5, an aqueous solution containing 35 wt %H₂O₂, is injected into the flue gas stream 4 via spray nozzles in theflue gas ductwork, and is introduced in an amount that provides twomoles H₂O₂ per mole of residual NH₃ in the flue gas stream 4. TheH₂O₂-injection treatment shown in block C is sufficient to reduce theammonia content in the exiting gas stream 6 to about 3 ppm NH₃, comparedto 10 ppm NH₃ in the pre-treatment flue gas stream 4.

The flue gas stream 6 contains about 45 ppm NO_(X), about 3 ppm NH₃,about 890 ppm SO₂ and about 18 ppm SO₃, and is next subjected to atreatment with an alkali reagent. The alkali reagent 7 is particulatetrona that is pneumatically conveyed and injected as a dry powder intothe flue gas stream 6. The particulate trona, a natural mineralcontaining Na₂CO₃.NaHCO₃.2H₂O, is employed as a finely-milled powderhaving a mean particle size of less than about 40 μm.

The trona 7 is introduced into contact with the flue gas in a dryinjection operation D in the FIGURE, for further reduction of the NO_(X)content in the flue gas stream 6. The treated flue gas stream 8,downstream of the trona injection operation D, contains a reduced levelof NO_(X), less than 40 ppm NO_(X).

The flue gas stream 8 downstream of the trona injection operation D isnext passed through an air preheater E, a gas-gas heat exchange unitthat reduces the temperature of the flue gas stream 8 from about 700° F.to about 330° F. in the exit gas stream 9. The cooling medium in the airpreheater E is air (not shown in the FIGURE) which is heated in the airpreheater E prior to its being directed to the combustion furnace toburn the coal.

The flue gas stream 9 exiting from the air preheater E is directed toone or more electrostatic precipitators (ESP), shown as block F labeledas ESP in the FIGURE, to remove entrained solids, i.e., particulates,from the flue gas stream 9. The entrained solids in the flue gas stream9 include fly ash, from the coal combustion, and spent trona after itsreaction with NO_(X) in the flue gas stream. The solids-free ESP-treatedflue gas exits the electrostatic precipitator operation F as flue gasstream 10. The ESP solids, removed as stream 11, are disposed of in alandfill.

The ESP-treated flue gas stream 10, having a reduced, low NH₃concentration, also has its NO_(X) content significantly reduced, ascompared with the combustion flue gas stream 2 upstream of the SCRreactor B: the flue gas stream 10, downstream of the ESP operation F,contains about 3 ppm NH₃ and less than 40 ppm NO_(X).

The SO_(X)-containing flue gas stream 10 is preferably subjected to adesulfurization procedure (not shown in the FIGURE) to reduce its SO₂and SO₃ content before the flue gas stream is vented to the atmosphere.Wet desulfurization scrubbing operations using an alkali such as lime,limestone or soda ash, are well known procedures for desulfurizingSO_(X)-containing flue gas streams.

It will be appreciated by those skilled in the art that changes could bemade to the embodiments described above without departing from the broadinventive concept thereof. It is understood, therefore, that thisinvention is not limited to the particular embodiments disclosed but isintended to cover modifications within the spirit and scope of thepresent invention as defined by the appended claims.

What is claimed is:
 1. A method for removing NO_(X) from a flue gasstream comprising injecting ammonia or an ammonia-forming compound intoa combustion flue gas stream containing NO_(X), wherein an excess ofammonia is introduced into the flue gas stream as an agent for reducingthe NO_(X), to yield a flue gas stream containing unreacted residualammonia and a reduced concentration of NO_(X); thereafter injectinghydrogen peroxide into the flue gas stream containing unreacted residualammonia, the flue gas having a temperature of about 250° F. to about800° F.,in an amount sufficient to react with residual ammonia presentin the flue gas stream, to yield an ammonia-depleted flue gas stream;and contacting the ammonia-depleted flue gas stream with an alkalireagent in an amount sufficient to remove NO_(X) present in the gasstream, yielding a flue gas stream with reduced concentrations ofammonia and NO_(X).
 2. The method of claim 1 wherein the ammonia isintroduced into flue gas stream in an amount sufficient to provide atleast about 50% stoichiometric molar excess, based on the amount ofNO_(X) present in the flue gas stream.
 3. The method of claim 1 whereinthe combustion flue gas stream temperature during the ammonia injectionoperation is between about 300° F. to about 1200° F.
 4. The method ofclaim 1 wherein the hydrogen peroxide is employed as an aqueous hydrogenperoxide solution in combination with an activator.
 5. The method ofclaim 1 wherein the hydrogen peroxide is injected into theammonia-containing flue gas stream in an amount sufficient to provide atleast about ¼ mole H₂O₂ per mole NH₃ up to about 15 moles of H₂O₂ permole NH₃ present in the flue gas stream.
 6. The method of claim 1wherein sufficient hydrogen peroxide is contacted with theammonia-containing flue gas stream to reduce the ammonia concentrationin the H₂O₂-treated flue gas stream to less than about 10 ppm NH₃. 7.The method of claim 1 which further comprises injecting the ammonia intothe flue gas stream in conjunction with a selective catalyst reductionoperation used to treat the combustion flue gas stream.
 8. The method ofclaim 7 wherein the combustion flue gas stream temperature during theselective catalyst reduction operation is between about 300° F. to about800° F.
 9. The method of claim 7 wherein sufficient hydrogen peroxide iscontacted with the ammonia-containing flue gas stream to reduce theammonia concentration in the H₂O₂-treated flue gas stream to less thanabout 5 ppm NH₃.
 10. The method of claim 1 wherein the alkali reagent isselected from the group consisting of soda ash, trona, sodiumsesquicarbonate, nahcolite, sodium bicarbonate, wegscheiderite, lime,slaked lime, limestone and mixtures of these.
 11. The method of claim 1wherein the alkali reagent is contacted with the flue gas stream as adry sorbent, by injection of dry particulate sorbent having a meanparticle size of less than about 100 μm into the flue gas stream. 12.The method of claim 1 wherein the alkali reagent is contacted with theflue gas stream as a slurry of particulate sorbent in admixture withwater, by injecting or spraying the reagent-containing slurry into theflue gas stream.
 13. The method of claim 1 wherein the alkali reagent iscontacted with the flue gas stream as a solution of the reagent at leastpartially dissolved in an aqueous medium, by injecting or sprayingreagent-containing solution into the flue gas stream.
 14. The method ofclaim 1 wherein the alkali reagent is contacted with the flue gas streamas a solution or slurry of the reagent in an aqueous medium in a wetscrubber or absorber.
 15. The method of claim 1 wherein sufficientalkali reagent is contacted with the ammonia-depleted flue gas stream toreduce the NO_(X) concentration in the alkali reagent-treated flue gasstream to less than about 50% of the NO_(X) concentration in theammonia-depleted flue gas stream.
 16. The method of claim 1 wherein thealkali reagent is introduced into the ammonia-depleted flue gas streamand which further comprises subjecting the flue gas stream to a solidsrecovery operation following the introduction of the reagent.
 17. Themethod of claim 16 wherein the solids recovery operation is selectedfrom the group consisting of baghouse filtration and electrostaticprecipitation.
 18. The method of claim 1 wherein the NO_(X)-containingflue gas stream further comprises SO_(X) as a contaminant and whichfurther comprises subjecting the NO_(X)-depleted flue gas stream to adesulfurization operation.